# LAKE CHARLES LNG COMPANY, LLC — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 420173002
- **title:** LAKE CHARLES LNG COMPANY, LLC — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2017-02-21
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 192.463(a), 193.2605, 193.2629(a)(2)(ii), 193.2635(d), 193.2707(a), 193.2713, 193.2717, 193.2801, 193.2911.
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- **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-420173002.md
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- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/420173002
**body:**

Notice of Probable Violation involving LAKE CHARLES LNG COMPANY, LLC. PHMSA's enforcement data identifies the cited regulations as 192.463(a),  193.2605,  193.2629(a)(2)(ii),  193.2635(d),  193.2707(a),  193.2713,  193.2717,  193.2801,  193.2911. The case was opened on 2017-02-21 and is reported as closed as of 2020-11-09. Proposed civil penalty: $32,400. Assessed civil penalty: $32,400. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420173002_Closure Letter_11092020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Closure%20Letter_11092020.pdf

420173002_Closure Letter_11092020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Closure%20Letter_11092020_text.pdf

420173002_Decision on Petition for Reconsideration_04272020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Decision%20on%20Petition%20for%20Reconsideration_04272020.pdf

420173002_Decision on Petition for Reconsideration_04272020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Decision%20on%20Petition%20for%20Reconsideration_04272020_text.pdf

420173002_Final Order_12022019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Final%20Order_12022019.pdf

420173002_Final Order_12022019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Final%20Order_12022019_text.pdf

420173002_NOPV PCP PCO_02212017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_NOPV%20PCP%20PCO_02212017.pdf

420173002_NOPV PCP PCO_02212017_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_NOPV%20PCP%20PCO_02212017_text.pdf

420173002_Operator Petition for Reconsideration and Request for Stay_12232019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Operator%20Petition%20for%20Reconsideration%20and%20Request%20for%20Stay_12232019.pdf

420173002_Operator Pre-Hearing Submittal_09222017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Operator%20Pre-Hearing%20Submittal_09222017.pdf

420173002_Operator Response to Notice and Request for Hearing_03222017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Operator%20Response%20to%20Notice%20and%20Request%20for%20Hearing_03222017.pdf

420173002_Operator_Post-Hearing_Brief_11032017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Operator_Post-Hearing_Brief_11032017.pdf

420173002_Closure Letter_11092020_text.pdf

Via ELECTRONIC MAIL
November 9, 2020
Matthew Ramsey
Chief Operating Officer
Energy Transfer Partners, LP
8111 Westchester Drive
Dallas, Texas 75225
CPF 4-2017-3002
Dear Mr. Warren:
On March 7, 2018, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued
to Lake Charles LNG Company, LLC a Final Order in the above-referenced case. This Final Order
included a Compliance Order that required the respondent to complete all items and to submit
documentation to the Southwest Region Director demonstrating the completion within 180 days
of receiving the Final Order and a civil penalty.
On June 1, 2020, Lake Charles LNG provided documentation addressing completion of all items
referenced in the Compliance Order. Based on our review of the information provided, it has been
determined that you have complied with the terms the Compliance Order and made payment of
the penalty, therefore, this case is now considered closed.
Thank you for your cooperation in this matter.
Sincerely,
Mary L. McDaniel, P.E.
Director, Southwest Region
Pipeline and Hazardous Materials Safety Administration
cc: Todd Nardozzi, Director Regulatory Compliance, Energy Transfer

420173002_NOPV PCP PCO_02212017_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
February 21, 2017
Mr. Dennis Odum
VP, Operations of the South and LNG Divisions
Lake Charles LNG Company, LLC
800 E. Sonterra Blvd
San Antonio, TX 78258
CPF 4-2017-3002
Dear Mr. Odum:
On September 15 - 16, 2015, a representative of the Pipeline and Hazardous Materials Safety
Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United
States Code inspected your records and procedures in Lake Charles, Louisiana.
As a result of the inspection, it appears that you have committed probable violations of the Pipeline
Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable
violation(s) are:
1. §193.2629 External corrosion control, buried or submerged components
(a) Each buried or submerged component that is subject to external corrosive attack
must be protected from external corrosion by:



(2) The following means:
(ii) A cathodic protection system designed to protect components in their entirety in
accordance with the requirements of §192.463 of this chapter and placed in operation
before October 23, 1981, or within 1 year after the component is constructed or installed
whichever is later.
§192.463 External corrosion control: Cathodic protection.
(a) Each cathodic protection system required by this subpart must provide a level of
cathodic protection that complies with one or more of the applicable criteria
contained in Appendix D of this part. If none of these criteria is applicable, the
cathodic protection system must provide a level of cathodic protection at least equal
to that provided by compliance with one or more of these criteria.
Appendix D - Criteria for Cathodic Protection and Determination of Measurements
I. Criteria for cathodic protection
(1) A negative (cathodic) voltage of at least 0.85 volt, with reference to a saturated
copper-copper sulfate half cell. Determination of this voltage must be made with the
protective current applied, and in accordance with sections II and IV of this appendix.
II. Interpretation of voltage measurement.
Voltage (IR) drops other than those across the structure electrolyte boundary must be
considered for valid interpretation of the voltage measurement in paragraphs A(1) and
(2) and paragraph B(1) of section I of the appendix.
Lake Charles LNG failed to consider IR drop when interpreting cathodic protection readings from
their annual survey to determine if the cathodic protection was adequate as required by §193.2629
and §192.463, Appendix D. During the inspection, the Operator stated that they were using the -
0.85 volt criterion with current applied. This criterion requires that voltage (IR) drops other than
those across the structure to electrolyte boundary be considered for valid interpretation of the
voltage measurements. PHMSA requested information on how the Operator had considered IR
drops in determining the adequacy of the readings, but the operator was unable to explain or
provide additional information in the form of surveys, studies, or measurements to show how this
requirement had been satisfied.
2



The -0.85 volt criterion at a minimum requires this potential at the pipe-to-soil interface. Readings
taken on the surface of the ground above the pipe incorporate a voltage drop that if not considered,
could result in the required cathodic protection potential at the pipe-to-soil interface being
inadequate. Lake Charles LNG’s records show only structure to soil readings with the cathodic
protection current applied and the Operator did not account for the voltage (IR) drops in the
cathodic protection circuit, particularly IR drop in the soil between the point of measurement on
the surface of the ground and the pipe.
2. §193.2635 Monitoring corrosion control
Corrosion protection provided as required by this subpart must be periodically
monitored to give early recognition of ineffective corrosion protection including the
following, as applicable:
(d) Each component that is protected from atmospheric corrosion must be inspected at
intervals not exceeding 3 years.
Lake Charles LNG failed to periodically inspect a portion of their aboveground piping to monitor
for ineffective corrosion protection from atmospheric corrosion as required by §193.2635. During
the PHMSA inspection, the Operator was asked to provide atmospheric corrosion inspection
records for their aboveground piping, specifically the insulated stainless steel piping used to
transport chilled or liquefied natural gas within the facility. Lake Charles LNG responded by
stating that the stainless steel piping will not corrode and consequently did not require inspection
for atmospheric corrosion. This assumption is also documented in the Lake Charles LNG’s
Technical Procedures Manual, Section 8.1 Component Identification, which shows that the
Operator did not require atmospheric corrosion inspections of the stainless steel piping.
The Lake Charles LNG facility has a significant quantity of aboveground insulated stainless steel
piping that has not been periodically inspected for atmospheric corrosion. The insulation generally
consists of a fibrous material wrapped around the circumference of the pipe covered by aluminum
sheathing held onto the piping by metal straps (Exhibit B, Photos 1 – 5). This covering, while
necessary to help preserve the temperature of the chilled or liquefied natural gas, makes it difficult
to visually inspect the piping for atmospheric corrosion. However, insulated piping is susceptible
to a specific type of atmospheric corrosion called Corrosion Under Insulation (CUI) and must be
periodically inspected for corrosion just as with other aboveground piping. CUI is recognized by
industry as a serious damage mechanism that results from the presence of moisture trapped under
insulation and can adversely affect the integrity of piping by providing an environment conducive
to corrosion, particularly environments that contain chlorides or sulfides. The location of the Lake
Charles LNG facility is in an environment that includes high humidity (making it likely that
condensation will form on the pipe) and potential sources of chlorides (the nearby brackish or salt
water in Calcasieu Lake and the Gulf of Mexico).
3



The justification provided by the Operator for concluding that the stainless steel piping will not
corrode was primarily based on the argument that the operating temperature at the Lake Charles
LNG facility is not within the range where stainless steel piping is susceptible to corrosion. The
source referenced by the Operator for this conclusion was a study by the Norwegian University of
Science and Technology titled “Pitting and Crevice Corrosion of Stainless Steel under Offshore
Conditions”1 authored by a graduate student at the Norwegian University of Science and
Technology as a Master’s thesis (see Exhibit B, Pitting and Crevice Corrosion of Stainless Steel
under Offshore Conditions, Norwegian University of Science and Technology, Trondheim 2012).
The Operator refers to Figure 2.5 in the document that shows the Critical Pitting Temperature
(CPT) and the Crevice Corrosion Temperature (CCT) for various grades of un-welded stainless
steel. Lake Charles argues that their operating temperatures range from -255 degrees F (-159
degrees C) to -50 degrees F (-46 degrees C) but the CPT and CCT for 304 Stainless Steel from
Figure 2.5 are 4 degrees C and -16 degrees C, respectively, making their operating temperatures
too low for corrosion to occur. When the PHMSA inspection was performed, the Lake Charles
LNG facility was not operating and the piping was at atmospheric
temperature, showing that the surface temperatures of the piping are not always within the range
stated by the operator.
The conclusions of the thesis referenced by the Operator do not support the argument that corrosion
of stainless steel can be predicted solely on the basis of operating temperature. In fact, the
referenced research was initiated because offshore operators were experiencing corrosion of
stainless steel piping under temperatures where existing charts and graphs indicated it wouldn’t
occur. The author states, “This study has shown that in order to be able to assess the possibility of
pitting and crevice corrosion and probability of failure with respect to time due to pitting corrosion
and coating degradation it is not enough to only consider temperature. It is shown that other
parameters are probably as important as temperature.” (Wika 73). The Operator also failed to
consider the stated limitations of the study. Specifically, the document states, “Only the bulk of
the pipe is considered, so welds, flanges and other places where localized corrosion is likely to
occur are out of scope for this study” (Wika 3). It is apparent that the Operator selected excerpts
from the referenced thesis to try and support their decision to not inspect the insulated stainless
steel piping, but failed to use the findings in a manner consistent with the complete results of the
research.
3. §193.2707 Operations and maintenance.
(a) Each operator shall utilize for operation or maintenance of components only those
personnel who have demonstrated their capability to perform their assigned functions
by-
(1) Successful completion of the training required by §§193.2713 and 193.2717;
(2) Experience related to the assigned operation or maintenance function; and,
(3) Acceptable performance on a proficiency test relevant to the assigned function.
1 Wika, Sandra Finsås (2012). Pitting and Crevice Corrosion of Stainless Steel under Offshore Conditions (Master’s Thesis) Norwegian University of Science and Technology.
Trondheim, 2012
4



§193.2713 Training, operations and maintenance.
(a) Each operator shall provide and implement a written plan of initial training to
instruct-
(1) All permanent maintenance, operating, and supervisory personnel-
(i) About the characteristics and hazards of LNG and other flammable fluids used or
handled at the facility, including, with regard to LNG, low temperatures, flammability
of mixtures with air, odorless vapor, boiloff characteristics, and reaction to water and
water spray;
(ii) About the potential hazards involved in operating and maintenance activities; and,
(iii) To carry out aspects of the operating and maintenance procedures under
§§193.2503 and 193.2605 that relate to their assigned functions; and
(2) All personnel-
(i) To carry out the emergency procedures under §193.2509 that relate to their assigned
functions; and
(ii) To give first-aid; and,
(3) All operating and appropriate supervisory personnel-
(i) To understand detailed instructions on the facility operations, including controls,
functions, and operating procedures; and
(ii) To understand the LNG transfer procedures provided under §193.2513.
(b) A written plan of continuing instruction must be conducted at intervals of not more
than 2 years to keep all personnel current on the knowledge and skills they gained in the
program of initial instruction.
§193.2717 Training, fire protection.
(a) All personnel involved in maintenance and operations of an LNG plant, including
their immediate supervisors, must be trained according to a written plan of initial
instruction, including plant fire drills, to:
(1) Know the potential causes and areas of fire;
(2) Know the types, sizes, and predictable consequences of fire; and
(3) Know and be able to perform their assigned fire control duties according to the
procedures established under § 193.2509 and by proper use of equipment provided
under § 193.2801.
(b) A written plan of continuing instruction, including plant fire drills, must be
conducted at intervals of not more than 2 years to keep personnel current on the
knowledge and skills they gained in the instruction under paragraph (a) of this section.
(c) Plant fire drills must provide personnel hands-on experience in carrying out their
duties under the fire emergency procedures required by § 193.2509.
Lake Charles LNG failed meet the training requirements required by the regulations. Lake Charles
LNG failed to provide records demonstrating that they had met all required initial and/or refresher
training according to §193.2707 and the Operator’s procedures as required by §193.2713 and
§193.2717. In addition, the Operator failed to require refresher training on detailed operations for
supervisors and the required training for security personnel was not in accordance with §193.2713.
5



Training records presented by Lake Charles LNG during the inspection did not show that personnel
had completed the required training as required by §193.2707 and defined by the facility’s training
matrix, Lake Charles LNG Company, Table 1.1, Master Training Matrix, Initial and Refresher
Training, Revised 02/01/2010. In addition, the Operator’s records did not show that supervisors
completed refresher training on detailed operations. Contract security personnel also have
assigned duties as part of the facility’s emergency response but there were no records showing that
security personnel received training on the Operator’s emergency procedures.
4. §193.2801 Fire Protection
Each operator must provide and maintain fire protection at LNG plants according to
sections 9.1 of NFPA 59A (incorporated by reference, see §193.2013). However, LNG
plans existing on March 31, 2000 need not comply with provisions on emergency
shutdown systems, water delivery systems, detection systems, and personnel
qualification and training until September 12, 2005.
§193.2605 Maintenance procedures.
(a) Each operator shall determine and perform, consistent with generally accepted
engineering practice, the periodic inspections or tests needed to meet the applicable
requirements of this subpart and to verify that components meet the maintenance
standards prescribed by this subpart.
(b) Each operator shall follow one or more manuals of written procedures for the
maintenance of each component, including any required corrosion control. The
procedure must include:
(1) The details of the inspections or tests determined under paragraph (a) of this section
and their frequency of performance; and
(2) A description of other actions necessary to maintain the LNG plant according to the
requirements of this subpart.
(c) Each operator shall include in the manual required by paragraph (b) of this section
instructions enabling personnel who perform operation and maintenance activities to
recognize conditions that potentially may be safety-related conditions that are subject to
the reporting requirements of §191.23 of this subchapter.
Lake Charles LNG failed to follow their procedures in performing and documenting verification
of the annual inspection of their emergency shutdown system. The Operator has a comprehensive
procedure for performing the annual inspection of their emergency shutdown system titled “ESS
II Shutdown System Procedure, Annual Inspection PM #860-74.” This procedure includes
sections for documenting the tests of the various components throughout the facility.
Documentation of the annual inspection performed on June 17, 2015 contained many blank fields
that were intended to be initialed by testing personnel to confirm proper operation and there were
no notes of explanation included with the documentation. Consequently, it cannot be determined
from the documentation whether the un-initialed components failed the testing, were skipped
during the testing, or could not be tested based on operating circumstances at the facility. The
Operator must have complete documentation according to their procedures and should include6



explanatory notes indicating any repairs or follow-up actions needed, why components weren’t
tested, and when they will be tested to comply with §193.2801 and their inspection procedures.
5. §193.2911 Security lighting.
Where security warning systems are not provided for security monitoring under
§193.2913, the area around the facilities listed under §193.2905(a) and each protective
enclosure must be illuminated with a minimum in service lighting intensity of not less
than 2.2 lux (0.2 ftc) between sunset and sunrise.
The Lake Charles LNG inspection records for security lighting failed to show that the
Operator was in compliance with the requirements of §193.2911. When PHMSA requested
records for security inspections, Lake Charles LNG presented an inspection report performed
by Project Technical Liaison Technical Associates, Inc. (PTL) dated 04/15/2005. The
inspection document stated that PTL completed a review of the existing Trunkline LNG
facility for compliance to the amended sections of code. The only reference to the inspection
of security lighting is in the inspection section referring to NFPA 59A, 9.8.4 that states “LNG
facilities shall be illuminated in the vicinity of protective enclosures and in other areas as
necessary to promote security of the facility.” The comment in the PTL inspection states
“Light posts on the entire perimeter fencing are provided to identify suspected intrusion.”
There was nothing in the inspection record presented by Lake Charles LNG to confirm the
presence of a security warning system or lighting with a minimum intensity of 2.2 lux.
Proposed Civil Penalty
Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000
per violation per day the violation persists up to a maximum of $2,000,000 for a related series of
violations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed
$100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related
series of violations Also, for LNG facilities, an additional penalty of not more than $50,000 for
each violation may be imposed. The Compliance Officer has reviewed the circumstances and
supporting documentation involved in the above probable violation(s) and has recommended that
you be preliminarily assessed a civil penalty of $32,400 as follows for item 1.
Item number PENALTY
1 $32,400
Warning Items
With respect to items 4 and 5, we have reviewed the circumstances and supporting documents
involved in this case and have decided not to conduct additional enforcement action or penalty
assessment proceedings at this time. We advise you to promptly correct these item(s). Failure to
do so may result in additional enforcement action.
7



Proposed Compliance Order
With respect to items 1, 2, and 3 pursuant to 49 United States Code § 60118, the Pipeline and
Hazardous Materials Safety Administration proposes to issue a Compliance Order to Lake Charles
LNG. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this
Notice.
Response to this Notice
Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in
Compliance Proceedings. Please refer to this document and note the response options. All
material submit in response to this enforcement action may be made publicly available. If you
believe that any portion of your responsive material qualifies for confidential treatment under 5
U.S.C. 552(b), along with the complete original document you must provide a second copy of the
document with the portions you believe qualify for confidential treatment redacted and an
explanation of why you believe the redacted information qualifies for confidential treatment under
5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a
waiver of your right to contest the allegations in this Notice and authorizes the Associate
Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to
you and to issue a Final Order.
In your correspondence on this matter, please refer to CPF 4-2017-3002 and for each document
you submit, please provide a copy in electronic format whenever possible.
Sincerely,
R. M. Seeley
Director, Southwest
Pipeline and Hazardous Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings
8



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Lake Charles LNG a Compliance Order
incorporating the following remedial requirements to ensure the compliance of Lake Charles LNG
with the pipeline safety regulations:
1. 2. 3. 3. 4. In regard to Item Number 1 of the Notice pertaining to Lake Charles LNG’s failure
to consider IR drop when conducting an annual CP survey:
Survey the facility so that IR drop is considered in the readings and remediate any
areas not meeting the criterion. Implement provisions to consider IR drop in
determining the adequacy of all future readings in the form of procedures and
interrupted surveys or other accepted means of consideration.
In regard to Item Number 2 of the Notice pertaining to Lake Charles LNG’s failure
to provide procedures demonstrating that atmospheric corrosion inspections are
performed on a regular basis on above ground stain less steel insulated piping:
Develop procedures to inspect insulated above ground insulated stainless steel pipe
for atmospheric corrosion at set intervals not to exceed every 3 years. Using the
procedures, perform an atmospheric corrosion inspection of the insulated stainless
steel piping.
In regard to Item Number 3 of the Notice pertaining to Lake Charles LNG’s training
records:
Review training records for all personnel and confirm that the required initial
training and refresher training has been completed according to the requirements of
§193.2707, §193.2713, §193.2717, and the Operator’s training matrix. Ensure that
supervisors complete refresher training on detailed operations and that contract
Security personnel who have defined roles in the facility emergency response plan
have received training in the emergency response plan and their roles. Develop
records that clearly identify the employee’s job title, the specific training required
for that employee’s job, and the dates the initial and refresher training was
completed by each employee.
Lake Charles LNG must demonstrate within 180 days of receipt of this order that
the requirements of this Compliance Order have been completed for Item Numbers
1, 2 and 3.
It is requested (not mandated) that Lake Charles LNG maintain documentation of
the safety improvement costs associated with fulfilling this Compliance Order and
submit the total to R. M. Seeley, Director, Southwest, Pipeline and Hazardous
Materials Safety Administration. It is requested that these costs be reported in two
categories: 1) total cost associated with preparation/revision of plans, procedures,
studies and analyses, and 2) total cost associated with replacements, additions and
other changes to pipeline infrastructure.9

420173002_Final Order_12022019_text.pdf

December 2, 2019
Mr. Kelcy L. Warren
Chief Executive Officer
Energy Transfer, LP
8111 Westchester Drive
Dallas, Texas 75225
Re: CPF No. 4-2017-3002
Dear Mr. Warren:
Enclosed please find the Final Order issued in the above-referenced case. It withdraws one
allegation of violation, makes findings of violation, assesses a civil penalty of $32,400, and
specifies actions that need to be taken by your subsidiary, Lake Charles LNG Company, LLC, to
comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final
Order. When the civil penalty has been paid and the terms of the compliance order completed,
as determined by the Director, Southwest Region, this enforcement action will be closed.
Service of the Final Order by certified mail is effective upon the date of mailing as provided
under 49 C.F.R. § 190.5.
Thank you for your cooperation in this matter.
Sincerely,
Alan K. Mayberry
Associate Administrator
for Pipeline Safety
Enclosure
cc: Ms. Mary McDaniel, Director, Southwest Region, Office of Pipeline Safety, PHMSA
Mr. Jeff Brightwell, Vice President, LNG Operations, Lake Charles LNG Company,
LLC, 8100 Big Lake Road, Lake Charles, Louisiana 70605
Ms. Catherine D. Little, Esq., Troutman Sanders, LLP, 600 Peachtree Street, NE,
Suite 5200, Atlanta, Georgia 30308
CERTIFIED MAIL - RETURN RECEIPT REQUESTED



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
____________________________________
In the Matter of )
Lake Charles LNG Company, LLC, ) CPF No. 4-2017-3002
a subsidiary of Energy Transfer, LP, )
)
)
)
Respondent. )
____________________________________)
FINAL ORDER
On September 15-16, 2015, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and
Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),
conducted an on-site pipeline safety inspection of the facilities and records of Lake Charles LNG
Company, LLC (Lake Charles LNG or Respondent), in Lake Charles, Louisiana. At the time of
the inspection, the Lake Charles LNG facility encompassed a 400-acre site and consisted of four
insulated liquefied natural gas (LNG) tanks, two vaporizers, and associated equipment with
export facilities under development. Lake Charles LNG is a wholly-owned subsidiary of Energy
Transfer, LP, which owns and operates approximately 71,000 miles of natural gas, natural gas
liquids, refined petroleum, and crude oil pipelines.1
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated February 21, 2017, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice), which also included a warning pursuant to 49
C.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that
Lake Charles LNG had committed three violations of 49 C.F.R. Part 193 and proposed assessing
a civil penalty of $32,400 for one of the alleged violations. The Notice also proposed ordering
Respondent to take certain measures to correct the alleged violations. The Notice also included
two warning items that required no further action, but warned the operator to correct the probable
violations or face possible future enforcement action.
Lake Charles LNG responded to the Notice by letter dated March 22, 2017 (Response).
Respondent contested the allegations and requested a hearing. A hearing was subsequently held
on October 3, 2017, in Houston, Texas before a PHMSA Presiding Official. At the hearing,
Respondent was represented by counsel. Respondent submitted additional written materials
prior to the hearing on September 22, 2017 (Pre-hearing submittal), and following the hearing on
1 Pipeline Safety Violation Report (Violation Report), (Feb. 21, 2017) (on file with PHMSA), at 1; Energy Transfer,
LP website, available at https://www.energytransferlng.com/who we are html (last accessed November 12, 2019).



CPF No. 4-2017-3002
Page 2
November 3, 2017 (Post-hearing submittal). The Director submitted a region recommendation
on May 22, 2019 (Region recommendation), and Lake Charles LNG submitted a reply to the
region recommendation on May 31, 2019 (Reply).
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 193, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 193.2629(a), which states:
§ 193.2629 External corrosion control: buried or submerged
components.
(a) Each buried or submerged component that is subject to external
corrosive attack must be protected from external corrosion by—
(1) Material that has been designed and selected to resist the corrosive
environment involved; or
(2) The following means:
(i) An external protective coating designed and installed to prevent
corrosion attack and to meet the requirements of §192.461 of this chapter;
and
(ii) A cathodic protection system designed to protect components in
their entirety in accordance with the requirements of §192.463 of this
chapter and placed in operation before October 23, 1981, or within 1 year
after the component is constructed or installed, whichever is later.
The Notice alleged that Respondent violated 49 C.F.R. § 193.2629(a) by failing to protect its
pipeline from external corrosion by means of a cathodic protection system that met the
requirements of § 192.463. Specifically, the Notice referenced Appendix D of Part 192 and
alleged that Lake Charles LNG failed to consider IR drop when interpreting cathodic protection
readings from its annual surveys. IR drop represents the voltage difference between the pipe-to-
soil readings taken at the surface and the readings that one would actually obtain at the pipe-to-
soil interface due to the resistance of the soil. In the absence of considering IR drop, an operator
may erroneously conclude that the cathodic protection level meets the -850 mV criterion when it
does not, resulting in a failure to provide adequate cathodic protection to the pipe.2
In its Response and at the hearing, Lake Charles LNG stated that it began its 2015 annual
cathodic protection survey the day before the scheduled OPS compliance inspection began.
Respondent did not argue that it was not required to consider IR drop. Rather, Respondent
explained that it contracted with the firm Corrpro to install interrupters on its rectifiers during the
2015 inspection which would allow it to be able to measure IR drop. Respondent did not provide
the OPS inspector with any records, documents, studies, prior surveys, or explanations for how it
considered the effect of IR drop in interpreting the cathodic protection pipe-to-soil voltage
measurements, nor were any such documents provided in connection with the hearing. During
2 Region recommendation, at 3.



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the hearing, Respondent did not argue that its annual surveys conducted in years prior to 2015
accounted for IR drop.
The requirement to consider IR drop on an annual basis has been in place since before the
facility was commissioned in 1981. In Lake Charles LNG's case, its own records and statements
establish that it had never performed an interrupted survey in the history of the facility until
2015. Accordingly, after considering all of the evidence and the legal issues presented, I find
that Respondent violated 49 C.F.R. § 193.2629(a) by failing to protect its pipeline from external
corrosion by means of a cathodic protection system that met the requirements of § 192.463 prior
to the 2015 inspection and survey.
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 193.2635(d), which states:
§ 193.2635 Monitoring corrosion control.
Corrosion protection provided as required by this subpart must be
periodically monitored to give early recognition of ineffective corrosion
protection, including the following, as applicable:
(a)…
(d) Each component that is protected from atmospheric corrosion must
be inspected at intervals not exceeding 3 years.
The Notice alleged that Respondent violated 49 C.F.R. § 193.2635(d) by failing to periodically
inspect a portion of its aboveground piping to monitor for ineffective protection from
atmospheric protection. Specifically, the Notice alleged that Lake Charles LNG did not inspect
certain insulated piping used to transport liquefied natural gas at intervals not exceeding three
years.
In its Response and at the hearing, Lake Charles LNG contested the allegation, contending that
the aboveground pipe used to transport LNG at its Lake Charles facility was not required to be
periodically inspected for atmospheric corrosion. Respondent explained that it believed the three
year inspection requirement did not apply to stainless-steel pipe and that austenitic stainless steel
“contains a high percentage of nickel and chromium, and is thus extremely resistant to
corrosion.”3 Respondent cited a research paper entitled "Pitting and Crevice Corrosion of
Stainless Steel Under Offshore Conditions."4 This paper included a diagram in Figure 2.5
showing the temperatures that different grades of stainless steel were previously thought to be
susceptible to corrosion.5 For 304 stainless steel, the critical pitting temperature ranges from 5
degrees to -20 degrees C. Respondent explained that the operating temperature of its piping
during LNG operations is -46 degrees C to -159 degrees C, and argued that its piping was
3 Post-hearing submission, at 5. It is notable, however, that § 193.2635(d) does not include an express exemption
from the atmospheric corrosion inspection requirement for stainless steel pipe. If the drafters of this regulation had
intended to exempt stainless steel pipe from atmospheric corrosion inspections, they could have easily done so then
and there but they chose not to.
4 Violation Report, Exhibit B.
5 Id., at 18-19.



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operated outside the temperature range for corrosion to occur.
OPS acknowledged that cryogenic temperatures were a factor in preventing external pipe
corrosion, but pointed out that the Lake Charles facility had not operated at cryogenic
temperatures since 2012, making it approximately six years since the piping has been within the
temperature range that Respondent maintains would prevent corrosion. OPS went on to point
out that the research paper also states: “This study has shown that in order to be able to assess the
possibility of pitting and crevice corrosion and probability of failure with respect to time due to
pitting corrosion and coating degradation it is not enough to only consider temperature. It is
shown that other parameters are probably as important as temperature.”6 OPS then pointed to a
section of the paper explaining that the other mechanisms that can cause the protective chromium
oxide layer on stainless-steel piping to be compromised and lead to corrosion include: (1)
chemical attack, particularly from environments containing chlorides and sulfides; (2)
mechanical damage such as scratches or gouges on the surface of the pipe; and (3) heat such as
that from welding. The critical factors listed include, “Design of insulation system, insulation
type, temperature, environment (humidity, rainfall and chlorides from marine environment,
industrial environments containing high SO2) are critical factors.”7
This leads to the issue of whether the temperature, humidity, and marine environment factors
present at the site of the Lake Charles facility implicate a potentially corrosive atmospheric
environment. Respondent argued that the Lake Charles facility was not subject to a corrosive
atmospheric environment. Respondent submitted a report entitled “Evaluation of the
Susceptibility to Corrosion of Stainless Steel LNG Pipe Under All Operating Conditions at the
lake Charles Liquefied Natural Gas Facility.
8 The report stated: “The LC LNG Facility is
approximately 26 miles (42 km) from the Gulf of Mexico, as shown in Figure 1.”9 The report
goes on to state, “The corrosion rate of carbon steel diminishes by more than 97% when it is only
0.62 miles (1 km) from the water. Thus, the effects of seawater on LC LNG Facility Type 304
SS piping should be insignificant at 26 miles (42 km) from the Gulf of Mexico.”10
With regard to the potential for a corrosive atmospheric environment to be present, OPS stated:
The Lake Charles facility is located in a hot, humid environment
immediately adjacent to bodies of saltwater. The piping is covered by
metallic sheathed insulation that is not water tight and can trap moisture
against the surface of the pipe. The chlorides present in the salt water along
with the environment could clearly create an environment that would
chemically degrade the thin protective chromium oxide layer on the
stainless-steel piping and result in a damage mechanism defined by API
6 Id., at 73.
7 Id., at 170-171.
8 Post-hearing submittal, Exhibit 4.
9 Post-hearing submittal, Exhibit 4, at 6.
10 Id.



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Recommended Practice 571, "Damage Mechanisms Affecting Fixed
Equipment in the Refining Industry" as Corrosion Under Insulation (CUI)
(Violation Report, Ex. B, at 170-71). This industry standard clearly
id
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